To explore for oil and gas, operator drill a well by rotating a drillstring having a drill bit and drill collars to bore through a formation. In a common form of drilling called rotary drilling, a rotary table or a top drive rotates a drillstring, which has a bottom hole assembly (BHA) with increased weight to provide necessary weight on the assembly's bit. During the drilling operation, vibrations occurring in the drillstring can reduce the assembly's rate of penetration (ROP). Therefore, it is useful to monitor vibration of the drillstring, bit, and BHA and to monitor the drilling assembly's revolutions-per-minute (RPM) to determine what is occurring downhole during drilling. Based on the monitored information, a driller can then change operating parameters such as weight on the bit (WOB), drilling collar RPM, and the like to increase drilling efficiency.
Because the drillstring can be of considerable length, it can undergo elastic deformations, such as twisting, that can lead to rotational vibrations and considerable variations in the drill bit's speed. For example, stick-slip is a severe torsional vibration in which the drillstring sticks for a phase of time as the bit stops and then slips for a subsequent phase as the drillstring rotates rapidly. When it occurs, stick-slip can excite severe torsional and axial vibrations in the drillstring that can cause damage. In fact, stick-slip can be the most detrimental type of torsional vibration that can affect a drillstring.
For example, the drillstring is torsionally flexible so friction on the drill bit and BHA as the drillstring rotates can generate stick-slip vibrations. In a cyclic fashion, the bit's rotational speed decreases to zero. Torque of the drillstring increases due to the continuous rotation applied by the rotary table. This torque accumulates as elastic energy in the drillstring. Eventually, the drill string releases this energy and rotates at speeds significantly higher than the speed applied by the rotary table.
The speed variations can damage the BHA, the bit, and the like and can reduce the drilling efficiency. To suppress stick-slip, prior art systems, such as disclosed in EP 0 443 689, have attempted to control the speed imparted at the rig to dampen any rotational speed variations experienced at the drill bit.
In whirl vibrations (also called bit whirl), the bit, BHA, or the drillstring rotates about a moving axis (precessional movement) with a different rotational velocity with respect to the borehole wall than what the bit would rotate about if the axis were stationary. Such precessional movement is called forward whirl when faster compared to rotation where the bit axis is stationary and is called backward whirl if slower. Thus, in backward whirl, for example, friction causes the bit and BHA to precess around the borehole wall in a direction opposite to the drillstring's actual rotation. For this reason, backwards whirl can be particularly damaging to drill bits. Whirl is self-perpetuating once started because centrifugal forces create more friction. Once whirl starts, it can continue as long as bit rotation continues or until some hard contact interrupts it.
When detrimental vibrations occur downhole during drilling, operators want to change aspects of the drilling parameters to reduce or eliminate the vibrations. If left unaddressed, the vibrations will prematurely wear out the bit, damage the BHA, or produce other detrimental effects. Typically, operators change the weight on bit, the rotary speed (RPM) applied to the drilling string, or some other drilling parameter to deal with vibration issues.
Attempts to detect vibrations during drilling have used accelerometers in a downhole sensor sub to measure lateral acceleration during drilling and to analyze the frequency and magnitude of peak frequencies detected. Unfortunately, accelerometers in the downhole sensor sub are susceptible to spurious vibrations and can produce a great deal of noise. In addition, some of the mathematical models for processing accelerometer data can involve several parameters and can be cumbersome to calculate in real-time when a drilling operator needs the information the most. Lastly, the processing capabilities of hardware used downhole can be somewhat limited, and telemetry of data uphole to the surface may have low available bandwidth.
The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.